Oil wells (wellbores) are usually drilled with a drill string. The drill string includes a tubular member having a drilling assembly that includes a single drill bit at its bottom end. The drilling assembly typically includes devices and sensors that provide information relating to a variety of parameters relating to the drilling operations (“drilling parameters”), behavior of the drilling assembly (“drilling assembly parameters”) and parameters relating to the formations penetrated by the wellbore (“formation parameters”). A drill bit and/or reamer attached to the bottom end of the drilling assembly is rotated by rotating the drill string from the drilling rig and/or by a drilling motor (also referred to as a “mud motor”) in the bottom hole assembly (“BHA”) to remove formation material to drill the wellbore. A large number of wellbores are drilled along non-vertical, contoured trajectories in what is often referred to as directional drilling. For example, a single wellbore may include one or more vertical sections, deviated sections and horizontal sections extending through differing types of rock formations.
The drilling process causes significant wear on the each of the components of the drill string, in particular the drill bit and the BHA. Managing the wear and conditions that lead to premature failure of downhole components is a significant aspect in minimizing the time and cost of drilling a wellbore. Some of the conditions, often collectively referred to as “drilling dysfunctions,” that may lead to premature wear and failure of the drill bit and the BHA include excessive torque, shocks, bit bounce, bit whirl, stick-slip, and others known in the art.
Bit whirl, for example, is characterized by a chaotic lateral translation of the drill bit and the BHA, frequently in a direction opposite to the direction of rotation. Whirl may cause high shocks to the bit and the downhole tools, leading to premature failure of the cutting structure of the bit. Whirl may be a result of several factors, including a poorly balanced drill bit, i.e., one that has an unintended imbalance in the lateral forces imposed on the bit during the drilling process, the cutting elements on the drill bit engaging the undrilled formation at a depth of cut too shallow to adequately provide enough force to stabilize the bit, and other factors known to those having ordinary skill in the art. Additionally, bit whirl may be caused in part by the cutting elements on the drill bit cutting too deeply into a formation, leading the bit to momentarily stop rotating, or stall. During this time, the drill pipe continues rotating, storing the torque within the drill string until the torque applied to the bit increases to the point at which the cutting elements break free in a violent fashion. Oscillation between such sticking and slipping at a relatively high frequency, which may manifest in the form of vibrations in the drill string, is a phenomenon is known in the art as “stick-slip.”
When drilling with a fixed cutter, or so-called “drag” bit or other earth-boring tool progresses from a soft formation, such as sand, to a hard formation, such as shale, or vice versa, the rate of penetration (“ROP”) changes, and excessive ROP fluctuations and/or vibrations (lateral or torsional) may be generated in the drill bit. The ROP is typically controlled by controlling the weight-on-bit (“WOB”) and rotational speed (revolutions per minute or “RPM”) of the drill bit. WOB is controlled by controlling the hook load at the surface and RPM is controlled by controlling the drill string rotation at the surface and/or by controlling the drilling motor speed in the drilling assembly. Controlling the drill bit vibrations and ROP by such methods requires the drilling system or operator to take actions at the surface. The impact of such surface actions on the drill bit fluctuations is not substantially immediate. Drill bit aggressiveness contributes to the vibration, whirl and stick-slip for a given WOB and drill bit rotational speed. “Depth of Cut” (DOC) of a fixed cutter drill bit, is generally defined as the depth to which a cutting element of a drag bit, for example, a polycrystalline diamond compact (PDC) cutting element, enters the formation being cut as the bit rotates, and may also be characterized by a distance a bit advances into a formation over a revolution, is a significant contributing factor relating to the drill bit aggressiveness, in conjunction with back rake of the cutting element. Controlling DOC can prevent excessive formation material buildup on the bit (e.g., “bit balling”), limit reactive torque to an acceptable level, enhance steerability and directional control of the bit, provide a smoother and more consistent diameter borehole, avoid premature damage to the cutting elements, and prolong operating life of the drill bit.